In fluid extraction well installations there is a frequent requirement to control a small number of subsea hydraulic devices, typically valves for example, on a manifold or other structure from a well head tree, located typically 100 m distant from the manifold/structure. The traditional method of implementing this requirement is to install a hydraulic jumper between the tree and the manifold/structure hydraulic devices and use a tree ‘subsea control module’ (SCM) to control these devices.
FIG. 1 illustrates a traditional arrangement for control of hydraulic devices, in this example valves on a remote manifold. A tree 1 houses an SCM 2, which is connected to the manifold 3. Each valve 4 on the manifold 3 is fed via a hydraulic control line 5 such that a directional control valve (DCV) in the SCM 2 controls the operation of one valve 4. Each tree around the manifold would be connected similarly to a respective set of three valves. Historically, hose-type jumpers 5 have been employed to link the hydraulic control from the SCM to the manifold valves. However, with the current trend for subsea wells to be at greater depths, fluid well installation companies are specifying steel tube jumpers, which are extremely expensive, both to buy and to install.
The requirement to operate hydraulic devices remote from the well head means that additional DCVs have to be integrated into the SCM. In general, SCMs are designed and manufactured as ‘common’ in that they contain sufficient DCVs to meet the requirement of a typical well. However, when further remote devices have to be operated, the ‘common’ SCM has to be modified which incurs substantial design costs. If, on the other hand, the ‘common’ SCM is designed to accommodate additional remote devices, then in many ‘straightforward’ applications the surplus capacity makes the SCM more expensive.
Intelligent downhole systems are becoming more common and generally require three hydraulic functions, operating at high pressure (typically 10 k to 15 k psi), inside the SCM. Not all wells need an intelligent completion. It is usual to have a ‘common’ design of SCM, so in many cases these three functions are unused. Typically, an intelligent well system will also need an additional high pressure (HP) accumulator to ensure that operating the intelligent well does not adversely affect the ‘surface controlled sub-surface safety valve’ (SCSSV) which is also on the HP supply and vice versa.
FIG. 2 illustrates a traditional arrangement for the control of downhole hydraulic devices, in this example valves 6. The tree 1 carries an SCM 2, which is connected to the downhole valves 6 via hydraulic feeds 7.
It should be noted that such systems are not the only systems available, for example British Patent Application No. GB 0319622.7 describes a decentralized control system which does not use an SCM. Likewise the system as described in British Patent No. GB 2264737 describes a further system in which the SCM is replaced by a multiplicity of integrated electronic and hydraulic functions in modules, such as smaller and dedicated electronic units and hydraulic units. In contrast to these two described systems, while this invention also employs modules that contain electrically operated hydraulic functions and perhaps electronic functions in some embodiments, in the present invention they are under the control of an SCM.